Enhancing Wellbore Stability and Efficiency through Geomechanical Modeling and Casing Design Optimization (Case Study Southern Iraq)

Abstract Multiple issues have arisen during drilling in southern Iraq’s (F) oilfield. Most of these issues are connected to wellbore stability, including differential sticking, tight hole, and lost circulation. These issues have rendered nearly one-third of drilling operations fruitless. The development of a one-dimensional geomechanical model addresses these challenges and improves future drilling operations in this area. This work utilizes the geomechanical model to optimize drilling operation parameters and plan them in a way eliminate the wellbore stability problems. The approach adopted in this work is a 1D geomechanical model to predict the appropriate casing design and suggest a better mud weight using mechanical rock properties and stress analysis. The used geomechanical model evaluate the rocks mechanical properties and the primary stresses by using data and historical recorded drilling operations problems. Moreover, the rock strength parameters are also determined used extended leak off studies and empirical formulas. To estimate the mud pressure conditions for different wellbore inclinations, azimuths, and formations, the geomechanical model alters the in-situ stresses. This comprehensive research about mud pressure prediction allows for optimizing mud weight for each formation, and casing design in every area. Direct measurements (bulk density log, compressional slowness log, shear slowness log, gamma ray log, caliper log, and geological formation information) and petrophysical quality control checks are needed to develop the geomechanical model. Sonic log values are 55–120 s/ft, while gamma ray readings are 15–72 GAPI. From the formations geological evaluation, the density log provides an information about electron density. Where, in weak formations, in spite of UCS and Tensile Strength are 3000–4200 Psi, the Young’s Modulus and Poisson’s Ratio are low. Formation stiffness is positively connected with friction angle (sandstone, dolomite, shale, and limestone). Young’s Modulus and Poisson’s Ratio rock stress study yields vertical, maximum horizontal, and minimum horizontal stress values and pore pressure readings. Shale formations have 7550 Psi vertical stress, 6200 Psi maximum horizontal stress, and 5200 Psi lowest horizontal stress. The limestone layers have a vertical stress of 7800–8200 Psi, however the maximum horizontal stress is around 7000–7900 Psi, and a minimum horizontal stress is around 6000–7000 Psi. On the other hand, the pore pressure can be estimated direct and using hydrostatic methods. In this work case study, drilling mud used was heavy, therefore a pipe got trapped in the Dammam Formation and narrow regions in the Lower Fars Formation. Moreover, the pressure depletion in the Mishrif Formation caused wellbore differential sticking and washouts. The study using correlations and local data to determine the geomechanical features. The poro-elastic approach determines major horizontal stresses, however the extrapolation method determines vertical stress. The goemechanical model assesses mud pressure conditions and recommends mud weight and casing design for each formation segment. This assessment can work as a geo-proactive drilling model which help to prevent frequent wellbore stability issues, improve drilling efficiency and lower costs